SandRidge Energy, Inc. (SD) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the fourth quarter 2013 SandRidge Energy earnings conference call. [Operator Instructions] I would now like to turn the conference over to Mr. Duane Grubert, executive vice president of investor relations and strategy. Please proceed.

Thank you, operator. Welcome, everyone, and thank you for joining our call. This is Duane Grubert, EVP of investor relations and strategy here at SandRidge, and with me today are James Bennett, president and chief executive officer; Eddie LeBlanc, EVP and chief financial officer; and David Lawler, our EVP and chief operating officer. Keep in mind that today's call contains forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of the discussion of these measures can be found on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trusts. Now let me turn the call over to our CEO, James Bennett.

Thanks, Duane. Closing out 2013 and entering 2014, we’re delivering the plan we laid out to shareholders last May. The changes we’ve made to the business and the asset base are clearly taking hold. I think, in summary, we are executing. I want to recap some of the significant improvements and steps forward we’ve taken in the business in the last 12 months, and then tie that in to how that positions SandRidge going forward. First, we made the mid-continent the focus of the business. We sold noncore assets, we redirected our intellectual capital and dollars into the mid-continent. Second, we significantly reduced our cost structure. For example, our G&A expense in 2012 was $200 million, in 2013 it was $170 million, and this year it’s going to be about $135 million. Third, we reduced the overall level of risk in the business. We took our capex from $2.3 billion down to $1.5 billion, kept our leverage under 3x, and we high graded our drilling efforts, with significantly less drilling capital and rigs in the extension areas of the play. Importantly, we improved our capital efficiency and returns. This derisk development plan allowed us to greatly improve our results, both IP rates, reduced variability in well performance, and increasing our pipe type curve. Operationally, the teams have reduced LOE and well costs every quarter, and though taking $50,000 or $100,000 out of our well costs every couple of quarters may not sound like a lot, but when you do that over a couple of years and drill over 400 wells a year, it’s very impactful. And let me walk you through, on this capital efficiency theme, an example I like to use. In 2013, in the mid-continent, and you can get this number on page seven of the earnings release, we spent $844 million in the mid-continent. That’s all-in well costs, including all D&Cs, saltwater disposal infrastructure, workovers, and capitalized interest. So $844 million to drill 434 wells. That compares to 2012, when we spent $927 million to drill 396 wells. So in this improved capital efficiency them, we spent 9% less capital and drilled 10% more wells. We had a good year in terms of reserve adds. You will need to bear with us and pro forma out the Gulf of Mexico and Permian for our two divestitures we’ve done over the last 14 months, but taking those into account, we grew proved reserves to 377 million barrels of oil equivalent, up from 301 at year-end ’12. We produced, again on a pro forma basis, 23 million barrels of oil equivalent, but we added approximately 100 million barrels of oil equivalent net of revision, so that’s over a 425% reserve replacement. We did that all at under a $12 per BOE [finding] cost. Our PV-10 is $4.1 billion. That’s up from $2.9 billion. Again, this is all with assets that we own today. And finally, we expanded our opportunity set by adding to our focus area. We had over 100,000 acres in a new county, in Sumner County. It’s the great work of our geology and engineering teams who set up a test program that has now turned into a full development program. So this targeted appraisal program we talked about has worked. So recapping 2013 - I won’t go into all the details, David and Eddie will give you some more in a minute, and you can find it in the earnings release - but I couldn’t be more pleased with the execution of our team this year. We’ve exceeded our targets for the quarter and the year while coming in under our capex budget. The mid-continent production is growing. Fourth quarter grew 8% quarter over quarter. Our IP rates and production results continue to improve. We’re having success in six different zones in our mid-continent area. Our 2013 production, again pro forma, for the asset sales was 22.5 million barrels of oil equivalent, and that’s a 35% growth on this pro forma production for 2012, which would have been 16.5 million barrels. So again, 35% production growth pro forma year over year. Our pipe type curve improved. The EUR is up 3% total. Oil component is up 10%, and the rate of the return on the wells improved over 60%. Now, each part of the location we have has a PV of about 2.4 million. We’ve continued to optimize our saltwater disposal infrastructure. For the full year, the ratio of producers to disposals was 16:1, and 2013 that was 7:1. We now dispose of over 1 million barrels of produced water a day, and we view this system as a very valuable midstream asset within SandRidge’s [ENT] business. And finally, our costs keep coming down every quarter. So in looking back at 2013, why is it important to reflect on what we did in 2013? I think that our past success, I believe, is a leading indicator of future performance. And I think we executed and had a very successful 2013. So looking ahead to 2014 and beyond, right now we’ve got over 670,000 acres in our focus are position in mid-continent over a 10-year inventory of high return drilling locations and industry leading cost structure that allows us to drill these shallow wells for under $3 million each. The 2014 plan, where we could deliver over 25% production growth, at a similar growth rate in proved reserves. Given the operating leverage in the business, that’s going to translate into approximately a 35% growth in EBITDA year over year. And we have visibility into a multiyear plan that’s going to deliver similar growth rates. In terms of what to expect next week at the analyst day, I think we’ll have a lot of forward-looking discussion and analysis. Importantly, we’re going to have a multiyear outlook that’s going to give longer term visibility on our asset development and multiyear growth plan. You’ll hear more details on innovations coming out of our operational teams. You’ll get to meet and hear from our next layer of management and additional thoughts I’m going to give on our saltwater disposal position and assets, sizing this asset [not boughts] on unlocking the value there. It’s a formative day, next Tuesday in New York, and I hope you’ll join us in person or on the webcast. So, in closing, from me, from here forward, we’re going to be very focused on the following: first and most important, profitably growing our cash flows by converting our resource base into cash and asset value; capitalizing on our competitive advantages, our infrastructure and our knowledge base in this mid-continent area; continuing to improve our per unit cost measures, such as LOE, G&A, well costs, just to name a few; driving innovation and creating more upside, just like we did in 2013, finding new zones, success in the appraisal program, well designs and cost innovations. I think our saltwater disposal business falls into this same category of innovation. We identified a roadblock early on the play, which was it produced water, and invested early in this infrastructure and built a very valuable asset. Improving our leverage and balance sheet. We’re going to do that through growing our cash flows and asset base. And driving shareholder returns. Our job as manager is to allocate your capital in the highest risk-adjusted returns and we’re doing that. I’m confident that if we execute on the things above, our business and our shareholders will enjoy success. Let me turn the call over to our COO, Dave Lawler. Dave?

Thank you, James, and good morning to everyone joining us on the call. As we look back on our 2013 performance, it’s clear we’ve made significant progress across the business. We’re improving capital efficiency and creating value by expanding our resource base through a multizone appraisal program. Most importantly, we hit our targets. Not only did we exceed our year-end production guidance by 200 BOE, delivering a total of 33.8 million BOE, but also spent $26 million less than our $1.45 billion capital budget. The production delivered during the fourth quarter followed two consecutive quarters of increased guidance. These outcomes can be linked to a theme shared by the entire organization, that success is measured by meeting or exceeding our corporate targets. With this theme in mind, I would like to thank all of our employees for their exceptional work and their continual focus on running a safe operation. Beyond the guidance metrics, we also materially improved our midcontinent horizontal well costs and lease operating expense. In the fourth quarter, we delivered 80 wells for an average cost of $2.9 million. This cost was achieved with 85% of the wells being equipped with electric submersible pumps, which typically cost around $250,000. The latest round of cost reductions are primarily due to redesigned well site facilities and synchronized pad drilling. Looking back eight quarters to the first quarter of 2012, we have lowered total well costs by $1 [million] or 26% per well. This is a tremendous accomplishment by our teams, and reflects the emphasis we place on rate of return. In addition to well cost reduction, fourth quarter operating expense decreased to $6.91 per BOE. This is an all-time low for the company, and highlights the effectiveness of our development model and front-end engineering. Since most wells are connected to local power startup and produced water disposal systems are installed prior to the completion date, operating cost is not burdened with long term water hauling or expensive diesel generators. We are also pleased to report that our year-end 2013 PUD type curve for the Mississippian increased by 3% to 380,000 BOE with the oil volume increased by 10%. At $90 oil and $4 gas, a type curve drilled for $2.9 million yields and NPV of $2.4 million and a 57% rate of return. As discussed on earlier calls, well performance is steadily improving by targeting key reservoir characteristics and drilling in areas with high frequency of natural fractures. The impact of this refine process can be observed in the average 30-day IP for the quarter. This average was 386 BOE per day or 22% above the 2013 type curve. In terms of expanding our resource base, our subsurface teams continue to deliver significant value through our appraisal program. As you know, we’ve been focused efficiently on testing our vast acreage position. One area of particular interest is the eastern portion of the broader play in Sumner County, Kansas. To date, we have drilled five appraisal wells in this area. The wells delivered an average 30-day IP of 601 BOE per day. This rate is 90% above the 2013 type curve, and establishes the significant potential of the county. As a result, we are planning to drill 45 wells, adding 117,000 acres of high rate of return projects to our focus area. Combined with our previous Mississippian location count, we have many years of drilling ahead. The Chester program delivered strong results during the quarter as well. We now have five wells online, with an average 30-day IP of 337 BOE per day at 58% oil. To clarify, we’ve brought one Chester well online in the quarter, which delivered a 30-day IP of 589 BOE per day. We have moved three rigs into the area and expect to have 12 additional wells online by the end of the second quarter. SandRidge is the first mover on horizontal Chester development targeting oil, and we are now moving at full speed to capture value from this new resource. Aside from the Chester, we’ve completed two additional Woodford wells. A second tranche of test wells show a marked improvement above the first tranche. One well delivered a 30-day IP of 96 BOE per day at 67% oil, and the second well delivered an average 30-day IP of 190 BOE per day at 85% oil. More important than the individual rates, our subsurface teams have developed a geologic model that correlates the rock to the increased production. We believe that this model will further enhance Woodford performance during the next tranche of wells. We expect to have a total of nine wells online by the end of the second quarter. As we have shared previously, what makes our asset base compelling is that we have multiple formations to drill, and these opportunities are within our existing leased position. In addition, these formations can be developed with minimal infrastructure costs, since our produced water disposal and electric power distribution systems are already in place. Shifting now to our 2014 program, as outlined in the presentation linked to our earnings release, we are planning to increase production by 26% year on year on a pro forma basis with a capital program of $1.475 billion. The plans include 460 horizontal wells and 50 produced water disposal wells in the mid-continent, and 180 vertical wells in the Permian targeting [unintelligible] formation. This vertical well count will finish the obligation wells for the Permian royalty trust. In closing, we wanted to share that due to the exceptional work of our field teams, we have been able to overcome most of the serious challenges posed by the winter weather in the region, and we are leaving production guidance unchanged. The primary issue facing our team during the storms was the delay in securing rig [unintelligible] permits, but we have adjusted our program accordingly, and believe we can overcome most of this nonproductive time. We look forward to sharing more about our appraisal results and capital efficiency programs at our analyst day in New York on March 4. I’ll now turn the call over to Eddie LeBlanc, our chief financial officer. Eddie?

Thanks, Dave. Once again, I’m glad to be here to provide a financial summary for another quarter and a very good year. First, I want to remind everyone that when we speak of adjusted EBITDA it is net of noncontrolling interest, and when we refer to pro forma announced, we’re removing the effects of asset sold, which are primarily the Permian and Gulf assets. Since it’s important to understand the performance of the assets we retained, let’s discus pro forma results. For the fourth quarter 2013, pro forma adjusted EBITDA was $166 million versus $130 million from the same period in 2012. The improve was due to 27% increase in pro forma production for 6.1 million barrels of oil equivalent. The fourth quarter of 2013 also included a $32.7 million expense for an underdelivery penalty in connection with the [century plant]. Pro forma adjusted EBITDA for the full year 2013 was $609 million, a 67% increase over the $365 million for 2012, primarily due to a 35% increase in production to 22.5 million BOE and additionally to our cost reduction efforts such as with G&A expense. Total capital expenditures for 2013 were $1.424 billion, which was 2% better than guidance, and were also 35% less than 2012. Furthermore, in early 2013, we divested ourselves of the Permian assets and still we had growth in year over year production. At year-end 2013, we had $815 million of cash on hand. Another $737 million was added from net proceeds after working capital adjustment when we closed the Gulf assets [unintelligible]. So on a pro forma basis, year-end 2013 cash is $1.551 billion. We’ve made no draws on our bank credit facility. Currently, we only use the facility to support letters of credit, so the unused portion of our revolver borrowing base is $746 million. Pro forma liquidity at year-end 2013 is $2.3 billion. Total debt is $3.2 billion, with the earliest principal reduction due in 2020. And our pro forma net debt at year-end 2013 was $1.6 billion. Our leverage ratio at year-end 2013, on a pro forma basis, is 2.7. The details of our consolidated hedge position for 2014 and 2015 are included in our earnings release that was published last evening. However, I’d like to mention that we have hedged 94% of our 2014 anticipated liquids production volumes, which equates to 95% of 2014 estimated liquids revenue. We have had 65% of our 2014 anticipated natural gas production volumes which also have pushed to 65% of net estimated gas revenue. We’re making no changes to our current guidance, which was issued when we announced the sale of the Gulf assets, although for purposes of clarity, we are now including guidance for adjusted EBITDA for noncontrolling interest. After we close the first quarter of 2014, we will have further information regarding our ongoing [unintelligible] rates and if appropriate, we will publish any new guidance when we distribute first quarter 2014 earnings information in May. Operator, that concludes my remarks. Please open the question and answer period of the call.

[Operator instructions.] Your first question comes from the line of Neal Dingmann with SunTrust.

Just wondered, James, on the wells that you outlined, I think the 460 wells, could you give an idea of, again, versus the current core area versus Sumner County, I guess number one, and kind of reasonably where you’re going to be drilling these. And then number two, I think David mentioned a couple of the Chester wells, a couple of the new Woodford wells, wondered, in that group, just how much of the original core wells we’ll focus on versus some of these newer plays.

We’re planning to do the 45 wells in Sumner. It’s really a terrific area, and so we’ll push that really as much as we can, and we’ll let the well results guide where we ultimately end up. So we’ve got targeted the 45, but if we see significant success beyond what we’re expecting, we’ll channel more rigs in there. In terms of the broader play, we’re pretty well balanced. We have about a $50 million appraisal program to look at different sections, like the Woodford, the Chester, and others, the [unintelligible] that we’ve mentioned in the past. So it’s really a mix of opportunities and then we are pretty efficient at channeling the capex in the right direction. So like the Chester, when we see repeated success, then that’s where we start flowing the capex to.

And what I was getting at, I was wondering, just on kind of where the plans are to drill, in Kansas, where it maybe might be a bit more gassy. I was trying to reconcile that with the guidance that’s out there as far as how much you expect for both the overall growth but also then just on the oil and liquids volumes, how you will potentially see that expanding.

The ratio of states is probably around 3:1, but we have identified several parts of Kansas that are high oil production. We are the number one producer of oil in Kansas at this point. So I couldn’t speak exactly to product mix changing, but I can tell you that we’re trying to get as much oil in the system as we can. And we can give you a little more clarity on that next week in New York.

And on the Permian, you mentioned the 180 to sort of round out or close out the trust. Beyond that, I know there’s some potential there that you could continue to drill some of what I would call more so [on your own]. Will you continue that right on the heels of that? Or is that something you’ll evaluate and then go forward?

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Your next question comes from the line of Amir Arif with Stifel.

First, on the water side, the lower saltwater disposal drilling that you’re doing, is that changes due to water cuts, or are you simply just delaying the need to drill some of these wells? Or is the disposal [unintelligible] changing over time?

The water cut’s not changing. This is not a water drive reservoir, so we see a consistent water to oil ratio over the life of the wells, even as they decline. It’s a function of us getting more efficient with the system, changing some of the designs, drilling some lower cost disposal wells and really just being more methodical about how we develop the asset in advance of, and in conjunction with, developing our producing wells.

So what do you think that ratio will be on a sustained basis in terms of the need of some other disposal versus producer wells?

A couple of years ago, we said we wanted to get to 10:1. We’re clearly past that now. I think in this 15 to 21 range is a place we’re comfortable with. I would caution the group, though, on just using a producer to disposal ratio measure. We’ve got a new design of disposal wells we’ll talk about next week. It’s called a low cost alternative, where it’s a much more inexpensive well, but we’ll probably only connect three to six producers to it. But it’s very, very cost effective. So I think going forward, we’re going to talk about it as a percentage of capex. We’ll probably get away from this producer to disposal ratio, just because it’s going to be a little less meaningful as we use this low cost alternative. In 2012, our saltwater disposal capex, as a percentage of D&C capex, was 24%. In 2013 it was 12%. So we’re going to talk about it as a percentage of spending going forward. But we couldn’t be more pleased with the results of our saltwater and our engineering operational teams working together and optimizing that system. They’ve done a great job.

As a second question, on your improved EUR type curve, the higher oil you are, is that better IPs? Or is the decline rate outlook changed on your oil side?

I think it’s an IP increase, which results in about an 8% increase in the cume over the first year. So I don’t think it’s a change in the ultimate [band], more of an IP in first year production increase.

Just final question, on the core acreage, it’s obviously increase in terms of what you like. When do you have to make a decision on the remainder of your Mississippian Lime acreage in terms of explorations over renewals?

We’re in a good spot there. Let me just give you the stats. And I’ve given these before. I think it’s helpful to give people a full picture of the expirations. In the total play, we have 1.8 million acres. And I’m talking about the total play, not just the focus area, and I’ll give you the focus area as well. We have 715,000 acres expiring, but we have extensions on 75% of that at $117 an acre. We have in the whole play 21% HBP. That’s 53% in Oklahoma and 8% in Kansas. So specifically on the focus areas, we have 670,000 acres net. That’s 300,000 in Kansas, 370,000 in Oklahoma. I’m rounding just a hair there. 45% of that is HBP. 64% in Oklahoma and 25% of Kansas is HBP. In 2014, again in the focus area, we have 180,000 acres expiring with extensions on about 40% of that at 350 an acre. So in summary, we’ve got extensions on a lot of our acreage. We’ll extend some of that. We’ll let some expire and replace with some better acreage. You know, when we drill these good wells, a well comes in at 300, 500, 700 barrels a day, we go in and block up acreage around it. So we’ll let some acreage expire, and we’ll add in our better areas. In 2013, we added over 130,000 acres in our focus area at a cost of between $300 and $400 an acre. So we can still pick up acreage at reasonable costs.

Your next question comes from the line of Charles Meade with Johnson Rice.

If I could go back to the Sumner focus area, I was wondering two things. One, if you could share the oil/gas split for those first five wells there. And then second, given that this was not part of your original focus area, does this indicate that there may be some shift in your interpretation going forward? Or was it just the next area to test?

Remember, we had this extension program to test the rest of the acreage. And in the first quarter, really early second quarter last year, refined that extension program, and said, look, this is not working to develop all the way up into northwestern Kansas horizontally. Let’s refocus that. And we shrunk our extension program quite a bit. On average, we had 2.7 rigs drilling extension wells in the first quarter of the year. That average was 1.1 in the last quarter of ’13. So again, really refined the program. And the teams pulled it back into areas kind of closer to our focus, and saw some success in an appraisal well they drilled in Sumner. They had a theory on the geology and engineering around that, and did a great job evaluating it, testing it with several more wells. So this is a perfect example of what I think is a very balanced appraisal program. We’re going to spend in the neighborhood of $50 million to test and appraise some of these areas, and this is an example of where it worked. I think that was capital very well spent, and it added over 100,000 acres. So we’ll continue to do that, to have this balanced appraisal program with PUD drilling and some additional step outstanding. And Dave will give the data on the wells, if you have it.

Yes. We’ll provide the distribution at analyst day next week. We don’t have that in front of us at the moment. Or we can call you back. But what I will say is that it is a very high oil rate area. This is not a gas field, is why that wasn’t in there. It’s prolific oil production.

Got it. That’s what I was after. And then shifting over to the Chester, can you talk about what kind of formation that is, and how you selected those locations? I don’t want to steal from your analyst day next week at all, but the big question, and I’m sure it’s on your mind and on the mind of other people following you, is how much acreage might be prospective for results like this.

The Chester is part of the Mississippian package, but it’s not present across the entire play. It’s crops on the western portion of our acreage position. We haven’t disclosed the exact acreage position, but it’s pretty significant. And we have a pretty innovative team of geoscientists that have been mapping this and have identified the zone early. And they launched it last year. And we’re very, very excited about this. It’s a new concept. If you pull state records, you’ll see that there’s not very may horizontal Chester wells at all, and those that are in there are gas wells. And so we’re on the leading edge of this, and very impressive results. So we’ll go into more detail next week, but it’s a significant opportunity for us.

And this is a great example, to me, and you’ll hear directly from the guys in the team next week, of taking the learnings from the mid-continent experience we have, and horizontal oil applications, and applying that to the new formation, new zone, within our focus areas. I think it’s a great example of kind of the innovation and the work that the teams are doing that we hope to continue.

And what county were those? Were those two test wells in the same county?

Yeah, and we have five total. There was one in the quarter. And those are in Woods County.

Your next question comes from the line of Curtis Trimble with Global Hunter.

Just wanted to see if I could get some granularity on the changes in the type curve and maybe a breakdown of what was attributed to better initial well performance vis-à-vis the tail end of the curve hanging in there better, see if you could disaggregate that for us.

We mentioned that earlier, happy to repeat it. It’s mostly due to higher IPs and a higher cume in the first year. So our IP rate is up, and the first year cume is up about 8%. So that’s predominantly the change. It’s not much change in the band of the ultimate declines of the wells.

And this is across all or the majority of your [unintelligible] locations? It’s just not for that 600,000 plus focus area?

Correct, but I would say that most of the PUDs are in that 670 focus area.

Sure, but you just haven’t high graded and taken out the crappy wells in order to [unintelligible] your type curve is what I’m getting at.

Right. And as we noted, we did write off some PUDs. We high graded our PUD inventory and wrote off PUDs that were at the bottom end of the economics and we wouldn’t have hid in a five-year drilling plan. So we do have better PUDs than we did last year, and we did write off some of those PUDs that we won’t get to in five years.

Your next question comes from the line of Adam Duarte with Omega.

Just a quick question on the balance sheet. Given the state that the balance sheet is in, and the EBITDA growth that you guys expect, and it sounds like maybe some monetization or some value creation through the saltwater disposal, how do you think about what you have on the balance sheet in terms of the proceeds and the use of those proceeds and splitting that between drilling more wells, adding to your extension areas, paying down debt, or buying back stock?

Let me break that into two parts. On the balance sheet, with our $2.5 billion of liquidity, and even embedded in that liquidity I think we are underutilized in terms of senior credit capacity. So we use this term $2.5 billion liquidity. It could easily be higher than that today if we wanted it to. Again, no reason to increase our revolver size today, sitting on our cash balance. So plenty of liquidity. As we grow for the next few years, I told you, our EBITDA growth this year will be in the 35% zipcode, and we’re going to continue to grow at the similar 20-25% production growth rate and higher than that EBITDA. As we roll that forward for a couple few years, you get a lot of EBITDA growth, which allows you to very comfortably grow into the balance sheet and keep your leverage in check. And you won’t hear me talking a lot about, you know, two years ago, that’s all we spent our time talking about, was funding deficits and leverage. Now that’s all under control. It’s not one of the top five things we’re worried about. In terms of what to do with the capital, in terms of our capital allocation decisions, one is size, what’s the right amount of capital to spend, we think in that $1.5 billion zipcode. That’s a very comfortable place for us. It’s efficient for our operating teams, it allows Dave and his team to keep costs under control and keep things running smoothly. Also, it affords us a reasonable growth rate, growth in terms of production and growth in terms of reserves and value. And given where we are right now in terms of outspend, and the returns that we’re seeing on these assets, you know, over 60% drilling Mississippian wells, that’s our PUD IRR, I think the best outcome for shareholders for right now is for us to deploy this capital into the assets and grow that asset base, grow the production and grow the reserves and PV base. I think that’s the best outcome for shareholders right now. That could change as market circumstances change, but right now we think that’s the best path forward.

Your next question comes from the line of Arun Jayaram with Credit Suisse.

I was wondering if you could just quickly remind us the capex related to the trust going forward, and just the impact on the carry in ’14 and ’15.

A couple of things. We will wrap up the trust spending this year. I believe it’s about $140 million this year. We’ll be done with it after that point. Last year, it was over $300 million. So our trust capex is going down considerably. That allows us to redirect that capital into wells that are 100% SandRidge, working net revenue interest wells as opposed to 20%. So a lot more financial gearing from every capital dollar we spend. So that’s on the plus side in terms of our capex. The carry does go away this year. We have about $200 million left that will be done in the August timeframe. I think the combination of the trust, capex falling away, and these continued efficiencies we’ve seen are going to offset any loss in the trust. Some people say, how can you continue to spend $1.5 billion and grow, we think your capex needs to go a lot higher. That’s not the case. We’re very comfortable with this $1.5 billion zipcode. One is because of the trust’s spending, as I said, falling away. But we’ve gotten a lot more efficient. As I said in the call, $100,000, $200,000 savings in well costs when you drill $400,000 wells adds a lot of firepower to your capital plan. And plus, our more efficient spending on the infrastructure.

And one thing that wasn’t intuitive to me was just the performance revision. Obviously appreciate the color around that, but can you just comment on that? You’re high grading, right? So your EURs and your oil piece of that moved up. Your well costs are down. So I was just a little bit surprised on the performance revisions.

Those were wells that we’re not going to get to in the five-year SEC timeline. As we drilled another 450 wells in the play, we’ve booked PUDs in better areas, better PUDs. There’s some PUDs in some outlying areas and some other parts of the play that we’re not going to get to in that five-year timeframe. And the new wells we have to drill are better economics and better returns. So we’re just not going to get those. So we did write off about 36 million barrels, but we added 117 million barrels, and there was 16 million deposit price revisions. So on balance, we’re 100 million barrels up. But again, it’s just from not meeting those in the five-year SEC timeframe.

Your next question comes from the line of Joe Allman with JPMorgan.

Just a quick question on the updated type curve. So if I read the release correctly, and if I hear you correctly, the EUR increase is not necessarily on the same wells. The EUR increase comes from just replacing some of the wells you’re not going to drill over the next five years with better wells that you are going to drill over the next five years. Is that correct?

No, it’s both. We did, as we said, eliminate some PUDs that we’re not going to get to, but the performance, the base performance of the asset, has improved. Our IP rates are up, our first year cume is up. If you noticed, as we reported last year, our 30-day IPs of 386 for the quarter and 366 for the year are significantly ahead of where the type curve was. So no, I think it’s a better performance in the asset.

So, James, if I looked at, say, a handful of wells, did you actually increase the EURs on those specific wells that were booked in 2012 as PUDs? Did you actually increase the EUR assumption on those same wells?

Yes.

And then in terms of the costs, in the fourth quarter I think you averaged $2.9 million. Does that include the water disposal? And what’s the assumption for costs for 2014 per well?

That did not include the water disposal. We break out the water disposal separate. I think we spent about $95 million in total on the water disposal system last year, but that’s just a D&C cost. It does not include the disposal. The assumptions for this year, I believe, are $3 million in our model. And that does assume some amount of appraisal and testing. It also assumes drilling in some areas that are a little deeper, maybe a little tighter. So we’ve got $3 million built into the plan for 2014.

Your next question comes from the line of Scott Hanold with RBC.

I don’t want to beat a dead horse here, but back to the revision on the PUD EUR, you increased it by 3% to 380,000 BOE, and it seemed like there were some PUDs that were taken off, and some in better areas that were put on. So what was the actual increase on the apples to apples wells, because 3% increase sounds a bit small when you’ve had a bit of high grading going on there.

Well, a 3% increase may sound small, but a 10% increase in oil is not small. And I’ll tell you, I would take a 3% increase, compound that over three or five years, all day long. So I’m very pleased with the results, and it’s not just high grading. It’s improved performance. Remember this 30-day IP point. Our IP on the previous PUD type curve was 270 BOE per day, roughly. Our average IP for 2013 was 366 per day. So we are getting better, drilling better results, drilling better wells, better completion methods, better targeting. We’re getting better at this.

Specifically, could you give an apples to apples view of a well last year versus this year, just the same well, what did that same well have for a change in PV that was booked.

The type curve is a combination of hundreds of wells, so I don’t know if I can pick out any one specific well. But the wells got better, and our type curve is higher. And the performance of our wells is better. So I guess I’m not quite following you. Our type curve is up.

What I think would be helpful is to take a look at the same wells that might have been on the PUD list last year versus this year and sort of aggregate those and say, all right, on the apples and apples wells, these are up X%, so we can get a sense of how much of that 3% was a bit of a high grade and how much is true incremental performance improvement. I appreciate the fact that you do have higher PUDs, because you have better wells you’re drilling, but it would be good to see if there’s actual performance change year over year on those PUDs.

Yeah, I understand. You know what? That’s a great topic for analyst day. We’ll be going through a deep dive in the reserves on analyst day, and I think we’ll give you the information that you need there in New York next Tuesday.

And one quickly on the PDPs. Was there a change in what was booked for the PDPs? Was there a revision on those year over year?

No. There was no change year over year.

Your next question comes from the line of Richard Tullis with Capital One.

James or Dave, could you talk about the costs related to the Sumner County wells, including the infrastructure incurred?

The Sumner County wells, starting off, were a little bit more expensive than our base program, because we did a pretty intensive evaluation program. And we also drilled a little bit longer laterals, which added to the cost. So they’re a little bit more expensive at this point than kind of the concentrated area in some of our other project or focus areas. So a little bit more expensive, at least initially. In terms of the infrastructure, that area does require some site generation, because it is so remote. And so we’re looking to expand that as we go forward, because it’s not as accessible as some other parts of the play.

In Sumner, on the saltwater disposal infrastructure, you’ll see from the teams on Tuesday, these specific examples are where they’ve implemented this low cost alternative saltwater disposal system that you’ll hear us talking more about. It’s very effective in some of these appraisal areas.

Did you receive any proved reserves for some of the new areas, say the Chester or Sumner County area? And if so, what were the reserves associated with the wells?

There’s a small amount of Chester in the reserves. I don’t have that exact number for you, but there are no Sumner County reserves in the year-end reserve report.

And then just lastly, if you could, walk through the change in the standardized measure of value year over year.

We’ll save the blood and guts of that for next week, but on a pro forma basis, you’ve got to back out what we sold. So back out Permian from last year and Gulf of Mexico from both years. It was $2.9 million, and now it’s $4.1 million. So we’ve got a lot of reconciliation next year on all the moves and all the different changes in the components there. We’ll go through that on Tuesday.

Your next question comes from the line of Greg Slavin with TPG Axon.

I wanted to ask about the Repsol guidance that came out earlier in the week. On their Q4 call, they talked about the Miss Lime net to them being 20,000 to 25,000 barrels a day by year-end 2016. Obviously they’re your JV partner across much of your acreage, and so I was trying to do the math, the working interest math, and I got to about 115,000 to 140,000 a day net for SandRidge by year-end 2016, which is a three-year production CAGR of 30% to 40%. So I don’t mean to front run your investor day, but I guess the first question is, did I do that math correctly, translating Repsol’s guidance to SandRidge production? And second, what’s the process for Repsol guidance? Are they taking your numbers here, or did they come up with this by themselves?

Great question. This just came out a couple of days ago. Repsol had their year end. And they said that they see 20,000 to 25,000 barrels of oil equivalent per day by the end of 2016. So if you do the math, they own about 14% roughly working interest. So if you gross that up and then net it back down by SandRidge’s working interest, we have about a 73% working interest. So if you take that range of 20,000 to 25,000, gross it up to their 14% working interest, take it down to our 73% working interest, you do, you get this kind of 110,000 to 135,000 or 140,000 BOE per day in ’16. Our guidance for ’14 for BOE per day for the whole year is 63,500 for the mid-continent. So their numbers are good, and they’re in line. And I’d be very pleased with being at the top of the range, and I think it’s consistent with what we’ll talk about next week. These are not our numbers though, these are Repsol’s numbers. They came up with them completely on their own. But I think it does correspond to what we’re talking about, and I think it reaffirms our belief in the play, in the growth of the play, in the development of the asset over the next several years.

Your next question comes from the line of Joe Allman with JPMorgan.

Just back to the updated type curve, to what do you attribute the improved IP rates? Are you doing any enhanced completions or is it just these wells are performing better than you had modeled?

We’ll give you some more details at analyst day. I think it’s a combination of that. The team has gotten better at targeting, changing completion methods in some parts of the play, [unintelligible] completions and other things, trying some different packer systems and completion techniques, better targeting, as I said. So we’ll give you the details at the analyst day. I think it’s a combination. We’ve got over 1,200 wells drilled in the play now, so we get smarter every year and every quarter, and better at this.

And then back to the cost issue, so you’re assuming $3 million per well. For the same type of well, is the well going to cost you $100,000 more in 2014? Or is it going to cost you a little bit more on average because you’re doing some extra stuff, you’re doing some completions differently than before?

We’ll talk about that on Tuesday, but it’s doing a little bit extra stuff. Dave mentioned these wells in Sumner County. We spent a lot of money on science, ran tracers, ran image logs. So we’re spending money up front to make sure we understand the rock and the reservoir. We’re drilling into slightly deeper and a little bit tighter parts of the play, maybe in the lower Miss. So I think it’s a mix of the wells that’s causing us not to project it at 2.8 or 2.9. I think our base Miss program, and Dave Lawler and his team will go through it next week, we’ve seen significant improvements in those well costs, in just a base Miss well. In some cases, drilling those for 2.6, 2.7.

And then in terms of number of locations that you have to drill in the Miss play, what’s the before and after?

Let’s save that one for analyst day. I think we have a very robust discussion on our inventory count and our locations for the next several years.

And then there’s something circulating about the subpoena. What’s that about? Is that something we should be concerned about?

We don’t think so. It’s early in the process. We don’t have any more information at all about the fact of the investigation other than what we’ve put in the 10-K.

What’s the topic there?

We don’t even know.

Your next question comes from the line of George [Wainridge] from KeyBanc. George [Wainridge] - KeyBanc : Can you give more color on the [unintelligible] water for the wells you drilled in the fourth quarter. And then are you seeing any difference versus the two [Woodford] wells in the third quarter?

I’ll turn this over to Dave. He’ll be better suited to answer this. The question is of the two Woodford wells that we’ve talked about in this batch, how is that different, what have we learned from batch one?

I may defer, I know you’ve heard that several times. We will have a specific presentation on this next week. But I think just early, we can comment that there is a certain geologic model that we’re targeting now that we’ve learned about initially. We have the Woodford over a vast portion of our lease hold. So we started out testing the different areas and quickly learned from what we’ve seen, what the results showed us, and now we’re starting to target a more specific area of the play. And that’s the reason that you see the improved performance. And we have several wells coming up here in Q2 that will test that theory and we’ll talk to that next week. But we are pretty excited. We think we’ve got a bead on it. George [Wainridge] - KeyBanc: So in terms of [unintelligible] zone well drilled in the Mississippian, [unintelligible] the Woodford, can you give more color on the wells in the upper Miss, middle Miss, and lower Miss? Because I don’t see it in the press release.

Let’s save that one for analyst day. I don’t want to keep putting it off, but we’ve got a very thorough discussion about all those zones at analyst day, if that’s okay.

Your next question comes from the line of [Andy Parr with Surveyor]. [Andy Parr - Surveyor]: On the Sumner program, I was curious, are those 45 wells substituted into this year’s program? I think you guys have been talking about 460 wells or something like that? Or have those been in there with the original 460 guidance?

The Sumner wells displaced other projects. In terms of the rate of return, it’s significant. The question was asked earlier what the oil content was, and it’s around 70% in Sumner.

And that’s not unusual. You know, as you go through the drilling program and learn more throughout the year, you adjust it accordingly. [Andy Parr - Surveyor]: I was just trying to reconcile that with the guidance. There wasn’t a guidance change, and the 90% uplift in the EUR, I was trying to reconcile that in my head.

Yeah, no guidance change. We just substituted for other wells. [Andy Parr - Surveyor]: And then secondly, I think it was a 386 rate for the quarter on the average well count. Does that include every well in the mid-con, Chester, Woodford, Mississippian? Or are those just Miss wells?

That’s every. We started giving that stat for all wells.

This concludes the Q&A portion of today’s call. I would now like to turn the call back over to Mr. James Bennett for any closing remarks.